Power Plant with Steam Generation and Fuel Heating Capabilities

ABSTRACT

A power plant includes a gas turbine including a turbine extraction port that is in fluid communication with a hot gas path of the turbine and an exhaust duct that receives exhaust gas from the turbine outlet. The power plant further includes a first gas cooler having a primary inlet fluidly coupled to the turbine extraction port, a secondary inlet fluidly coupled to a coolant supply system and an outlet in fluid communication with the exhaust duct. The first gas cooler provides a cooled combustion gas to the exhaust duct which mixes with the exhaust gas to provide an exhaust gas mixture to a heat exchanger downstream from the exhaust duct. The power plant further includes a fuel heater in fluid communication with the outlet of the first gas cooler.

FIELD OF THE DISCLOSURE

The present disclosure generally relates to a gas turbine power plantsuch as a combined cycle or cogeneration power plant. More particularly,the present disclosure relates to a power plant configured forgenerating steam and for providing thermal energy to a fuel heater.

BACKGROUND OF THE DISCLOSURE

A gas turbine power plant such as a combined cycle or cogeneration powerplant generally includes a gas turbine having a compressor, a combustor,a turbine, a heat recovery steam generator (HRSG) that is disposeddownstream from the turbine and a steam turbine in fluid communicationwith the HRSG. During operation, air enters the compressor via an inletsystem and is progressively compressed as it is routed towards acompressor discharge or diffuser casing that at least partiallysurrounds the combustor. At least a portion of the compressed air ismixed with a fuel and burned within a combustion chamber defined withinthe combustor, thereby generating high temperature and high pressurecombustion gas.

The combustion gas is routed along a hot gas path from the combustorthrough the turbine where they progressively expand as they flow acrossalternating stages of stationary vanes and rotatable turbine bladeswhich are coupled to a rotor shaft. Kinetic energy is transferred fromthe combustion gas to the turbine blades thus causing the rotor shaft torotate. The rotational energy of the rotor shaft may be converted toelectrical energy via a generator. The combustion gas exits the turbineas exhaust gas and the exhaust gas enters the HRSG. Thermal energy fromthe exhaust gas is transferred to water flowing through one or more heatexchangers of the HRSG, thereby producing superheated steam. Thesuperheated steam is then routed into the steam turbine which may beused to generate additional electricity, thus enhancing overall powerplant efficiency.

Regulatory requirements for low emissions from gas turbine based powerplants have continually grown more stringent over the years.Environmental agencies throughout the world are now requiring even lowerlevels of emissions of oxides of nitrogen (NOx) and other pollutants andcarbon monoxide (CO) from both new and existing gas turbines. One way tocontrol emissions may include pre-heating the fuel upstream from thecombustor.

Traditionally, due at least on part to emissions restrictions, the gasturbine load for a combined cycle or cogeneration power plant has beencoupled to or driven by steam production requirements for the powerplant and not necessarily by grid power demand. For example, to meetpower plant steam demand while maintaining acceptable emissions levels,it may be necessary to operate the gas turbine at full-speed full-loadconditions, even when grid demand or power plant demand for electricityis low, thereby reducing overall power plant efficiency.

BRIEF DESCRIPTION

Aspects and advantages of the disclosure are set forth below in thefollowing description, or may be obvious from the description, or may belearned through practice of the disclosure.

One embodiment is directed to a power plant. The power plant includes agas turbine having a compressor, a combustor downstream from thecompressor, a turbine disposed downstream from the combustor and anexhaust duct downstream from an outlet of the turbine. The turbineincludes a turbine extraction port that is in fluid communication with ahot gas path of the turbine. The exhaust duct receives exhaust gas fromthe turbine outlet and the turbine extraction port defines a flow pathfor a stream of combustion gas to flow out of the hot gas path. Thepower plant further includes a first gas cooler having a primary inletthat is fluidly coupled to the turbine extraction port, a secondaryinlet fluidly coupled to a coolant supply system and an outlet in fluidcommunication with the exhaust duct. The first gas cooler provides acooled combustion gas to the exhaust duct, wherein the cooled combustiongas mixes with the exhaust gas to provide an exhaust gas mixture to aheat exchanger disposed downstream from the exhaust duct. The powerplant further includes a fuel heater disposed downstream from the outletof the first gas cooler. The fuel heater receives a portion of thecombustion gas or a portion of the cooled combustion gas and heats afuel upstream from the combustor.

Those of ordinary skill in the art will better appreciate the featuresand aspects of such embodiments, and others, upon review of thespecification.

BRIEF DESCRIPTION OF THE DRAWINGS

A full and enabling disclosure, including the best mode thereof to oneskilled in the art, is set forth more particularly in the remainder ofthe specification, including reference to the accompanying figures, inwhich:

FIG. 1 is a schematic diagram of an exemplary gas turbine basedcogeneration power plant according to one embodiment of the presentdisclosure;

FIG. 2 is a simplified cross sectioned side view of a portion of anexemplary gas turbine according to at least one embodiment of thepresent disclosure; and

FIG. 3 is a schematic diagram of the exemplary gas turbine basedcogeneration power plant as shown in FIG. 1, according to one embodimentof the present disclosure.

DETAILED DESCRIPTION

Reference will now be made in detail to present embodiments of thedisclosure, one or more examples of which are illustrated in theaccompanying drawings. The detailed description uses numerical andletter designations to refer to features in the drawings. Like orsimilar designations in the drawings and description have been used torefer to like or similar parts within the disclosure. As used herein,the terms “first”, “second”, and “third” may be used interchangeably todistinguish one component from another and are not intended to signifylocation or importance of the individual components. The terms“upstream” and “downstream” refer to the relative direction with respectto fluid flow in a fluid pathway. For example, “upstream” refers to thedirection from which the fluid flows, and “downstream” refers to thedirection to which the fluid flows.

The terminology used herein is for the purpose of describing particularembodiments only and is not intended to be limiting. As used herein, thesingular forms “a”, “an” and “the” are intended to include the pluralforms as well, unless the context clearly indicates otherwise. It willbe further understood that the terms “comprises” and/or “comprising,”when used in this specification, specify the presence of statedfeatures, integers, steps, operations, elements, and/or components, butdo not preclude the presence or addition of one or more other features,integers, steps, operations, elements, components, and/or groupsthereof.

Each example is provided by way of explanation of the disclosure, notlimitation of the disclosure. In fact, it will be apparent to thoseskilled in the art that modifications and variations can be made in thepresent disclosure without departing from the scope or spirit thereof.For instance, features illustrated or described as part of oneembodiment may be used on another embodiment to yield a still furtherembodiment. Thus, it is intended that the present disclosure covers suchmodifications and variations as come within the scope of the appendedclaims and their equivalents.

In a conventional co-generation power plant, fuel and air are suppliedto a gas turbine. Air passes through an inlet of the gas turbine intothe compressor section upstream of combustors in the gas turbine. Afterthe air is heated by combustors, the heated air and other gases producedin the process (i.e., combustion gas) pass through the turbine section.The full volume of exhaust gas from the gas turbine passes from theturbine section to an exhaust section of the gas turbine, and flows to aheat recovery steam generator (HRSG) that extracts heat from the exhaustgas via one or more heat exchangers to produce steam.

In certain instances, the demand for steam may be lower than the amountof steam that could be generated by the gas turbine exhaust, some of theexhaust gas could be directed away from the heat recovery steamgenerator, such as being transported to an exhaust stack that filtersthe exhaust gas prior to being released into the atmosphere.Alternatively, if steam production is in higher demand than the steamgenerated by the gas turbine exhaust, then an increase in exhaust gasfrom the gas turbine could be produced to generate the steam desired.

The present embodiments provide a system to cool or temper hotcombustion gas extracted directly from a turbine of a gas turbine priorto being mixed with exhaust gas flowing from an outlet of the turbineand for providing a stream of cooled combustion gas to a fuel heater.Although the combustion gas is cooled via a gas cooler, the cooledcombustion gas is still significantly hotter than exhaust gas flowingfrom the turbine. As a result, the thermal energy from the cooledcombustion gas raises the temperature of the exhaust gas upstream from aheat exchanger/boiler and/or heat recovery steam generator (HRSG),thereby enhancing steam production from the gas turbine. In addition,the cooled combustion gas may be used to preheat a fuel provided to thecombustor or to some other fuel burning device.

The steam may be piped to a steam turbine, used for heat productionand/or for other industrial processes. The system can be used in acogeneration system such that the cogeneration system can produce ahigher quantity of steam without producing a proportional increase ofpower. The embodiment system thus provides an efficient use of the fuelinput into the cogeneration system, and avoids wasteful production ofundesired power by the gas turbine.

The embodiments provided herein provide various technical advantagesover existing cogenerations or combined cycle power plants. For example,the system provided herein may include the ability to modulate steamproduction at a desired level while maintaining thermal and otheroperating efficiencies; the ability to provide a higher temperature gasto produce more steam downstream of the gas turbine; the ability tooperate at a lower power output on the gas turbine and generate moresteam; the ability to minimize wasteful products (i.e., producingunnecessary power in the gas turbine); the ability to preheat fuelupstream form a combustor or burner; and the ability to operate acogeneration system at a more cost effective and efficient capacity.

Referring now to the drawings, wherein identical numerals indicate thesame elements throughout the figures, FIG. 1 provides a functional blockdiagram of an exemplary gas turbine power plant 10 with steam productioncapability. The power plant 10 comprises a first gas turbine 100 thatmay incorporate various embodiments of the present disclosure. The firstgas turbine 100 generally includes, in serial flow order, a compressor102, a combustion section having one or more combustors 104 and aturbine 106. The first gas turbine 100 may also include inlet guidevanes 108 disposed at an inlet or upstream end of the compressor 108. Inoperation, air 110 flows across the inlet guide vanes 108 and into thecompressor 102. The compressor 102 imparts kinetic energy to the air 110to produce compressed air as indicated schematically by arrows 112.

The compressed air 112 is mixed with a fuel such as natural gas from afuel supply system to form a combustible mixture within the combustor(s)104. The combustible mixture is burned to produce combustion gas asindicated schematically by arrows 114 having a high temperature,pressure and velocity. The combustion gas 114 flows through variousturbine stages S1, S2, S3, Sn of the turbine 106 to produce work.

The turbine 106 may have two or more stages, for example, a low pressuresection and a high pressure section. In one embodiment, the turbine 106may be a two-shaft turbine that includes a low pressure section and ahigh pressure section. In particular configurations, the turbine 106 mayhave 4 or more stages. The turbine 106 may be connected to a shaft 116so that rotation of the turbine 106 drives the compressor 102 to producethe compressed air 112. Alternately or in addition, the shaft 116 mayconnect the turbine 106 to a generator (not shown) for producingelectricity. The combustion gas 114 loses thermal and kinetic energy asit flows through the turbine 106 and exits the turbine 106 as exhaustgas 118 via an exhaust duct 120 that is operably coupled to a downstreamend of the turbine 106.

The exhaust duct 120 may be fluidly coupled to a first heat exchanger orboiler 122 via various pipes, ducts, valves and the like. The heatexchanger 122 may be a standalone component or may be a component of aheat recovery steam generator (HRSG). In various embodiments, the heatexchanger 122 is used to extract thermal energy from the exhaust gas 118to produce steam 124. In particular embodiments, the steam 124 may thenbe routed to a steam turbine 126 via various pipes, valves conduits orthe like to produce additional power or electricity. At least a portionof the steam 124 may be piped from the heat exchanger 122 to an onsiteor offsite facility 128 that distributes the steam to users and/orutilizes the steam for secondary operations such as heat production orother industrial operations or processes. In one embodiment, the steam124 may be piped downstream from the steam turbine 126 and furtherutilized for various secondary operations such as heat production orother secondary operations.

Steam flow rate or output from the heat exchanger 122 may be monitoredvia one or more flow monitors. For example, in one embodiment, a flowmonitor 130 may be provided downstream from the heat exchanger 122. Inone embodiment, a flow monitor 132 may be disposed downstream from thesteam turbine 126.

FIG. 2 provides a simplified cross sectional side view of a portion ofan exemplary first gas turbine 100 including a portion of the compressor102, the combustor 104, the turbine 106 and the exhaust duct 120 as mayincorporate various embodiments of the present disclosure. In oneembodiment, as shown in FIG. 2, the turbine 106 includes an innerturbine casing 134 and an outer turbine casing 136. The inner and outerturbine casings 134, 136 extend circumferentially about an axialcenterline 12 of the first gas turbine 100. The inner turbine casing 134and/or or the outer turbine casing 136 at least partially encasesequential rows of stator vanes and rotor blades that make up thevarious stages S1, S2, S3, Sn of the turbine 106.

The turbine casings 134, 136 are normally sealed with only two openings:a combustion gas inlet at the upstream of the turbine 106, and anexhaust gas or turbine outlet at a downstream end of the turbine 106.The downstream end of the turbine 106 is operably connected to theexhaust duct 120. Conventionally, the entire volume of combustion gas114 passes through a hot gas path 138 defined by the various stages ofthe turbine 106 within the inner and outer turbine casings 134, 136,into the exhaust duct 120 and at least a portion of the exhaust gas 118may be directed out of the exhaust duct 120 to the heat exchanger 122.

During operation, if it is determined that the demand for steamproduction is higher than the demand for power produced by the first gasturbine 100 a portion of the combustion gas 114 may be extracted fromone or more of the turbine stages S1, S2, S3, Sn via one or morecorresponding turbine extraction ports 140 as shown in FIG. 2. Fourturbine extraction ports 140(a-d) are shown for illustration. However,the turbine 106 may include any number of turbine extraction ports 140.For example, the turbine 106 may include one turbine extraction port140, two turbine extraction ports 140, three turbine extraction ports140 or four or more turbine extraction ports 140. Each turbineextraction port 140 is fluidly coupled to and/or in fluid communicationwith one or more of the turbine stages S1, S2, S3, Sn. Each turbineextraction port 140 provides a flow path for a stream of the combustiongas 114 to flow out of the turbine 106 from a point that is downstreamfrom the combustor 104 but upstream from the exhaust duct 120.

As shown in FIG. 2, one or more of the turbine extraction ports 140(a-d)may be in fluid communication with one or more of the turbine stages S1,S2, S3 or Sn via one or more extraction pipes 142. The extractionpipe(s) 142 and the turbine extraction ports 140 provide for fluidcommunication of the combustion gas 114 from the hot gas path 138,through the inner and/or outer turbine casings 134, 136 and out of theturbine 106 to obtain a portion of the combustion gas 114 at highertemperatures than the exhaust gas 118 flowing into the exhaust duct 120from outlet of the turbine 106.

As shown in FIG. 2, the stages in the turbine 106 are successive suchthat the combustion gas 114 flows through the stages from S1 to a laststage Sn. Turbine stage S1 is the first stage and receives hotcombustion gas 114 directly from the combustor 104. Temperature of thecombustion gas 114 decreases with each successive stage. For example,the combustion gas 114 at the S1 turbine stage has a higher temperaturethan at the subsequent turbine stages, S2, S3, Sn, etc. . . . Theexhaust gas 118 is at a lower temperature than the combustion gas 114within the turbine 106 and therefore has less thermal energy.

FIG. 3 provides a functional block diagram of the exemplary gas turbinepower plant 10 with steam production capability as shown in FIG. 1,according to one embodiment of the present disclosure. In oneembodiment, as shown in FIGS. 1, 2 and 3, the power plant 10 includes afirst gas cooler 144. The first gas cooler 144 includes a primary inlet146 fluidly coupled to one or more of the one or more turbine extractionports 140, a secondary inlet 148 fluidly coupled via various pipes,conduits, valves or the like to a coolant supply system 150, and anoutlet 152 in fluid communication with the exhaust duct 120 via variouspipes, conduits, valves or the like. In one embodiment, the first gascooler 144 comprises an ejector.

In one embodiment, the first gas cooler 144 comprises a static mixer.The static mixer generally includes individual mixing elements stackedin series within an outer casing or pipe and in fluid communication withthe primary and secondary inlets 146, 148 and with the outlet 152. Eachmixing element may be oriented relative to an adjacent mixing element tohomogenize two or more fluids flowing through static mixer.

The coolant supply system 150 provides a coolant 154 to the secondaryinlet 148 of the first gas cooler 144. In particular embodiments, asshown in FIGS. 1 and 3, the coolant supply system 150 comprises anambient air supply system 156 for collecting and/or conditioning ambientair upstream from the secondary inlet 148 of the first gas cooler 144.In particular embodiments, as shown in FIGS. 2 and 3 the coolant supplysystem 150 includes the compressor 102 of the first gas turbine 100. Thecompressor 102 may be fluidly coupled to the secondary inlet 148 of thefirst gas cooler 144 via one or more compressor extraction ports 158 andvia various pipes, conduits, valves or the like.

The compressor extraction port(s) 158 provide a flow path for a portionof the compressed air 112 to flow out the compressor 102 at a pointbetween an upstream or inlet to the compressor 102 and an outlet of thecompressor 102 that is defined upstream or immediately upstream from thecombustor 102. Because the compressed air 112 increases in pressure andtemperature from the inlet to the outlet, the compressor extractionport(s) 158 may be axially spaced along the compressor 102 at variouspoints to capture a portion of the compressed air 112 at a desiredtemperature and pressure.

In operation, the extracted combustion gas 114 from the one or moreturbine extraction ports 140 acts as a motive fluid flowing through thefirst gas cooler 144. Ambient air from the ambient air supply 156 or aportion of the compressed air 112 extracted from the compressorextraction port 148 flows into the secondary inlet 148 of the first gascooler 144 and cools the stream of combustion gas 114 upstream from theexhaust duct 120 and may also increase mass flow from the first gascooler 144 into the exhaust duct 120. A cooled combustion gas 160 flowsfrom the outlet 152 of the first gas cooler 144 and is routed into theexhaust duct 120 at a higher temperature than the exhaust gas 118. Thecooled combustion gas 160 mixes or blends with the exhaust gas 118within the exhaust duct 120 to provide a heated exhaust gas mixture 162to the heat exchanger 122 disposed downstream from the exhaust duct 120.Thermal energy from the cooled combustion gas 160 increases thetemperature of the exhaust gas 118, thereby increasing steam productioncapability of the power plant 10.

In particular embodiments, as shown in FIG. 3, the coolant supply system150 may include a second gas cooler 164 disposed downstream from thecompressor extraction port(s) 158 and upstream from the secondary inlet148 of the first gas cooler 144. The second gas cooler 164 may befluidly coupled to the compressor extraction port(s) 158 and to thesecondary inlet 148 of the first gas cooler 144 via various pipes,conduits, valves or the like. The second gas cooler 164 includes aprimary inlet 166 fluidly coupled to the compressor extraction port(s)158, a secondary inlet 168 in fluid communication with the ambient airsupply system 156 and an outlet 170 in fluid communication with thesecondary inlet 148 of the first gas cooler 144.

In operation, the compressed air 112 from the compressor extractionport(s) 158 acts as a motive fluid through the second gas cooler 164.Air entering the secondary inlet 168 of the second gas cooler 164 fromthe ambient air supply system 156 cools the stream of compressed air 112upstream from the secondary inlet 148 of the first gas cooler 144,thereby enhancing cooling of the combustion gases 114 flowingtherethrough. The air flowing into the second gas cooler 164 may alsoincrease air mass flow from the compressor extraction port(s) 148 intothe first gas cooler 144.

In various embodiments as shown in FIGS. 1-3, the power plant 10includes a fuel heater 172 fluidly coupled via various pipes, conduits,valves or the like to and downstream from the extraction port(s) 140 ofthe turbine 106. In particular embodiments, the fuel heater 172 isfluidly coupled via various pipes, conduits, valves or the like to anddownstream from the outlet 152 of the first gas cooler 144. Inoperation, the fuel heater 172 receives at least a portion of thecombustion gas 114 and/or at least a portion of the cooled combustiongas 160 from the first gas cooler 144. Fuel 174 from a fuel supply 176passes through the fuel heater 172 and thermal energy is transferredfrom the combustion gas 114 and/or the cooled combustion gas 160 to thefuel 174, thereby providing a heated fuel 178 downstream from the fuelheater 172. The heated fuel 178 may then be routed to the combustor 104.The heated fuel 178 may reduce emissions and/or improve overallcombustor efficiency.

In particular embodiments, as shown in FIGS. 2 and 3, the power plant 10may further comprise a coolant injection system 180 disposed downstreamfrom the outlet 152 of the first gas cooler 144 and upstream from theexhaust duct 120. The coolant injection system 180 may include spraynozzles, a spray tower, a scrubber or other various components (notshown) configured to inject a coolant 182 from a coolant supply 184 intothe stream of cooled combustion gas 160 flowing from the outlet 152 ofthe first gas cooler 144, thereby further cooling the cooled combustiongas 160 upstream from the exhaust duct 120. In particular embodiments,the coolant injection system 180 may be disposed upstream from the fuelheater 172 so as to further cool the cooled combustion gas 160 and/orthe combustion gas 114 flowing thereto.

In particular embodiments, as shown in FIGS. 1-3, the coolant injectionsystem 180 includes a mixing chamber 186 fluidly coupled to andpositioned downstream from the outlet 152 of the first gas cooler 144and/or downstream from to the turbine extraction port(s) 140. The mixingchamber 186 may be fluidly coupled to the exhaust duct 120 via variouspipes, conduits, valves or the like. The mixing chamber 186 may beconfigured to blend the stream of cooled combustion gas 160 from thefirst gas cooler 144 outlet 152 and the coolant 182 from the coolantsupply 184 upstream of the exhaust duct 120. In this manner, the coolant182 may be used to further reduce or control the temperature of thecooled combustion gas 160 upstream from the heat exchanger 122, theexhaust duct 120 and/or the fuel heater 172. The coolant 182 may be anyliquid or gas that may be mixed with the cooled combustion gas 160 forits intended purpose. In one embodiment, the coolant 182 is water. Inone embodiment the coolant 182 comprises steam.

Referring to FIGS. 1 and 3, a controller 200 may be used to determinethe desired steam production capacity and/or to regulate flow of thecooled combustion gas 160 to the fuel heater 172 by generating and/orsending appropriate control signals to various control valves 188fluidly coupled to one or more of the turbine extraction ports 140, oneor more control valves 190, 192 of the coolant supply system 150, and/orto one or more control valves 194 upstream from the fuel heater 172fluidly coupled between the outlet 152 of the first gas cooler 144 andthe fuel heater 172 and/or one or more control valves 196 of the coolantinjection system 180.

The controller 200 may be a microprocessor based processor that includesa non-transitory memory and that has the capability to calculatealgorithms. The controller 200 may incorporate a General ElectricSPEEDTRONIC™ Gas Turbine Control System, such as is described in Rowen,W. I., “SPEEDTRONIC™ Mark V Gas Turbine Control System”, GE-3658D,published by GE Industrial & Power Systems of Schenectady, N.Y. Thecontroller 200 may also incorporate a computer system having aprocessor(s) that executes programs stored in a memory to control theoperation of the gas turbine using sensor inputs and instructions fromhuman operators.

In particular embodiments, the controller 200 is programmed to determinea desired temperature of exhaust gas required to generate the desiredamount of steam flow, to regulate combustion gas flow through valve(s)188, air or coolant flow through valve(s) 190, 192, cooled combustiongas flow to the fuel heater 172 via valve 194 and/or coolant flow fromthe coolant injection system 180 via control vale 196 so as to achievethe desired temperature of the exhaust gas mixture 162 being sent to theheat exchanger 122 and to achieve desired flow rate and/or temperatureof the cooled combustion gas 160 and/or combustion gas 114 to the fuelheater 172.

In operation, as shown in FIGS. 1, 2 and 3 collectively, the controller200 may receive one or more input data signals, such as cooledcombustion gas temperature or combustion gas temperature 202, 204 fromtemperature monitors 300, 302 (FIGS. 1-3) disposed downstream from theoutlet 152 of the first gas cooler 144, exhaust gas mixture temperature206 from a temperature monitor 304 (FIGS. 1-3) disposed downstream fromthe exhaust duct 120 and/or upstream from the heat exchanger 122,coolant temperature 208 from a temperature monitor 306 (FIG. 3) disposeddownstream from the outlet 170 of the second gas cooler 164 and/ordownstream from the compressor extraction port 158, and/or heated fueltemperature 210 from a temperature monitor 308 (FIGS. 1-3) disposed ator downstream from the fuel heater 172.

The controller 200 may also receive steam flow data 212 from flowmonitor 132 and/or steam flow data 214 from flow monitor 130. Inresponse to one or more data signals 202, 204, 206, 208, 210, 212, 214the controller 200 may actuate one or more of valve(s) 188, 190, 192,194, 196 to control one or more of combustion gas flow from the turbinestages S1-Sn, air or coolant flow rate into the first gas cooler 144secondary inlet 148, cooled combustion gas flow rate to the fuel heater172 and/or coolant flow rate from the coolant injection system 180 toproduce the desired temperature of the exhaust gas mixture 162 and/or toproduce the desired temperature and/or flow rate of the cooledcombustion gas 160 and/or the combustion gas 114 flowing to the fuelheater 172.

Steam flow output from the steam turbine 126 may be monitored via thecontroller 200 using flow monitor 132. Steam flow output to secondaryoperations may be monitored via the controller 200 using flow monitor130. Controller 200 may actuate one or more of valve(s) 188, 190, 192,194, 196 to control one or more of combustion gas flow from the turbinestages S1-Sn, air or coolant flow rate into the first gas cooler 144secondary inlet 148, cooled combustion gas flow rate to the fuel heater172 and/or coolant flow rate from the coolant injection system 180 toproduce the desired temperature of the exhaust gas mixture 162 and/or adesired steam output from the heat exchanger 122 based at least in parton flow output as measured by at least one of flow monitors 130, 132.

Data signals received by the controller 200, such as combustion gastemperature, cooled combustion gas temperature, exhaust gas temperature,mixed exhaust gas temperature, steam flow rate and/or heated fueltemperature may be analyzed to compare with a predetermined desiredamount of steam flow and/or to a predetermined desired heated fueltemperature. The controller 200 may use the received data signals todetermine if an increase in exhaust gas temperature and/or an increaseor decrease in heated fuel temperature would be desired. Calculationsinclude determining the quantity of steam needed and the amount of powerdesired, and determining the temperature and quantity of combustion gasneeded to produce the desired quantity of steam and/or for heating thefuel 174 to a desired temperature.

After determining the desired temperature and quantity of combustion gas114 required for the heat exchanger 122 to produce desired steamquantity and/or to heat the fuel 174 to a desired temperature, thecontroller 200 may generate and send one or more signals 216, 218, 220,222 (FIGS. 1 and 3) to the receiver of the appropriate valve(s) 188 toextract combustion gas 114 through the turbine casings 134, 136 at theappropriate turbine stage S1, S2, S3, Sn. The controller 200 may sendsignals 224, 226 to the receiver of either or both valves 190, 192 tocontrol the flow rate of the coolant 154 flowing into the secondaryinlet 148 of the first gas cooler 144.

The controller 200 may also send a signal 228 to valve 194 to modulateflow of the combustion gas 114 and/or the cooled combustion gas 160 fromthe outlet 152 of the first gas cooler 144 to the fuel heater 172. Thecontroller 200 and/or the system or systems provided hereinautomatically blend the exhaust gas 118 with the stream of cooledcombustion gas 160 so that the exhaust gas mixture temperature is abovea nominal exhaust gas temperature but below the thermal limits of theheat exchanger 122 or HRSG while providing a stream of combustion gasand/or a stream of cooled combustion gas to the fuel heater 172.

Although specific embodiments have been illustrated and describedherein, it should be appreciated that any arrangement, which iscalculated to achieve the same purpose, may be substituted for thespecific embodiments shown and that the disclosure has otherapplications in other environments. This application is intended tocover any adaptations or variations of the present disclosure. Thefollowing claims are in no way intended to limit the scope of thedisclosure to the specific embodiments described herein.

What is claimed:
 1. A power plant, comprising: a gas turbine including acompressor, a combustor downstream from the compressor, a turbinedisposed downstream from the combustor and an exhaust duct downstreamfrom an outlet of the turbine, the turbine including a turbineextraction port in fluid communication with a hot gas path of theturbine, wherein the exhaust duct receives exhaust gas from the turbineoutlet and wherein the turbine extraction port defines a flow path for astream of combustion gas to flow out of the hot gas path; a first gascooler having a primary inlet fluidly coupled to the turbine extractionport, a secondary inlet fluidly coupled to a coolant supply system andan outlet in fluid communication with the exhaust duct, wherein thefirst gas cooler provides a cooled combustion gas to the exhaust duct,wherein the cooled combustion gas mixes with the exhaust gas to providean exhaust gas mixture to a heat exchanger disposed downstream from theexhaust duct; and a fuel heater disposed downstream from the outlet ofthe first gas cooler, wherein the fuel heater receives a portion of thecombustion gas or a portion of the cooled combustion gas and heats afuel upstream from the combustor.
 2. The power plant as in claim 1,wherein the heat exchanger extracts thermal energy from the exhaust gasmixture to produce steam.
 3. The power plant as in claim 1, furthercomprising a steam turbine disposed downstream from first heatexchanger.
 4. The power plant as in claim 1, wherein the first gascooler comprises an ejector.
 5. The power plant as in claim 1, whereinthe first gas cooler comprises an inline static mixer.
 6. The powerplant as in claim 1, wherein the coolant supply system comprises anambient air intake system fluidly coupled to the secondary inlet of thefirst gas cooler.
 7. The power plant as in claim 1, wherein the coolantsupply system comprises the compressor of the gas turbine, wherein thecompressor is fluidly coupled to the secondary inlet of the first gascooler via a compressor extraction port.
 8. The power plant as in claim1, wherein the coolant supply system comprises a second gas coolerhaving a primary inlet fluidly coupled to the compressor, a secondaryinlet fluidly coupled to an ambient air intake system and an outlet influid communication with the secondary inlet of the first gas cooler. 9.The power plant as in claim 10, wherein the second gas cooler comprisesan ejector.
 10. The power plant as in claim 10, wherein the second gascooler comprises an inline static mixer.
 11. The power plant as in claim1, wherein the turbine comprises an inner casing, an outer casing and anextraction pipe in fluid communication with at least one turbine stageof the turbine, wherein the extraction pipe is in fluid communicationwith the turbine extraction port.
 12. The power plant as in claim 1,further comprising a coolant injection system disposed downstream fromthe first gas cooler outlet and upstream from the exhaust duct, whereinthe coolant injection system injects a coolant into the stream of cooledcombustion gas flowing from the first gas cooler outlet.
 13. The powerplant as in claim 12, wherein the coolant is water.
 14. The power plantas in claim 12, wherein the coolant is steam.
 15. The power plant as inclaim 1, further comprising a controller electronically coupled to acontrol valve that is fluidly connected between the outlet of the firstgas cooler and the fuel heater and electronically coupled to atemperature monitor disposed downstream from the fuel heater, whereinthe controller generates a signal which causes the control valve toactuate based at least in part on a temperature data signal provided bythe temperature monitor to the controller.
 16. The power plant as inclaim 1, further comprising a controller electronically coupled to afirst control valve fluidly connected between the turbine extractionport and the first gas cooler primary inlet and a second control valvedisposed upstream from the secondary inlet of the first gas cooler. 17.The power plant as in claim 16, further comprising a temperature monitorelectronically coupled to the controller and in thermal communicationwith the turbine extraction port upstream from the exhaust duct, whereinthe controller actuates at least one of the first control valve toincrease or decrease the stream of combustion gas from the turbine andthe second control valve to increase or decrease mass flow through thesecondary inlet of the first gas cooler in response to a temperaturedata signal provided by the temperature monitor.
 18. The power plant asin claim 16, further comprising a steam flow monitor disposed downstreamfrom the first heat exchanger and electronically coupled to thecontroller, wherein the controller actuates at least one of the firstcontrol valve and the second control valve in response to a flow outputsignal provided to the controller by the steam flow monitor.